Dissolved oil removal from quench water of gas cracker ethylene plants

ABSTRACT

A method for removing dissolved hydrocarbons from water may comprise: cracking a mixed hydrocarbon stream in a cracking furnace to produce a cracked gas effluent; quenching the cracked gas effluent in a quench water tower with quench water to produce a quenched gas stream and a spent quench water stream comprising water, tars, heavy aromatic hydrocarbons, gasoline, dissolved oil, and dispersed oil; feeding the spent quench water stream to a liquid-liquid extraction unit wherein the liquid-liquid extraction unit removes at least a portion of the dissolved oil and produce an extracted effluent stream.

BACKGROUND

Dissolved Oil Removal (DOR) Unit is an additional liquid-liquidextraction process, using aromatic rich hydrocarbon solvent, that mayremove reactive dissolved hydrocarbons from pretreated net quench waterused in the process of dilution steam generation of steam crackerplants. The step of pretreating may remove dispersed oil from theaqueous phase of the net quench water.

Present technologies for pretreating net quench water may be describedas free dispersed oil coalescing units. Some units may include filtersfollowed by a coalescer, Dispersed Oil Extractor (DOX) system, andInduced Gas Floatation (IGF) system. All these units may coalescedispersed oil droplets in the net quench water and remove the coalescedoil from the net quench water. None of the aforementioned units arecapable of removing the dissolved oils that are in the bulk aqueousphase. Some of the hydrocarbons present in the bulk aqueous phase mayreact in units downstream of the coalescing unit which may cause foulingof dilution a steam generator and a gaseous hydrocarbon steam saturator.A DOR unit may be used to further treat pretreated net quench water toreduce the amount of dissolved hydrocarbons in the net quench water.Reduction or removal of dissolved hydrocarbons may reduce fouling of thedilution steam generator and the gaseous hydrocarbon steam saturator.

Base petrochemicals such as olefins (alkenes) may be produced in steamcracking plants from saturated aliphatic hydrocarbon feedstocks, such asethane, propane, butanes or higher molecular weight hydrocarbon mixturessuch as naphtha, atmospheric and/or vacuum gas oils, and the like.Generally, pressures may be close to atmospheric (e.g., from about 1.5to 2.5 barg.), and temperatures may be from approximately 700° C. toapproximately 870° C. Steam may be added to the hydrocarbon feed toreduce the hydrocarbon partial pressure. Steam-to-hydrocarbon feedratios may be generally 0.3-0.4:1 on a weight basis for lighthydrocarbon feedstocks such as ethane or propane, and butanes,respectively. The saturated hydrocarbon-steam mixture may be thermallycracked to lower molecular weight unsaturated hydrocarbons. Crackingproduct reactions may include ethylene predominately, followed bypropylene, and then various quantities of C₄, C₅ and C₆ mono- anddiolefinic hydrocarbons, with a lesser quantity of C₇ and higher weightsaturated and unsaturated aliphatic, cyclic and aromatic hydrocarbons.

Additionally, the thermal cracking process may produce some moleculesthat tend to combine to form high molecular weight materials which canbe categorized within the boiling range of “fuel oil” and heaviercompounds categorized as “tar”. Tar is a high-boiling point, viscous,reactive material that can foul equipment under certain conditions. Ingeneral, feedstocks containing higher boiling materials tend to producegreater quantities of tar. Unsaturated hydrocarbons are reactive and maypolymerize upon exposure to high temperatures which may cause fouling ofequipment.

One reason a steam cracking unit may be using ethane as a feedstock isbecause ethane is a co-product of natural gas from shale gas production,and has limited value for uses other than as a feedstock to a steamcracker unit. As natural gas demand and production rates grow forsupplying electrical power and home heating needs, ethane availabilitymay increase beyond its domestic regional demand. Since ethane cannot bereadily or economically transported, regional demand is important andwhere its availability exceeds regional demand, its price is reduced. Inmany regions, ethane feed costs may be 25% to 50% of other steam crackerfeedstocks such as propane, butanes or naphthas. This economic scenariogives rise to a large advantage to producing ethylene using low costethane feedstock. In addition, energy costs and capital investments fora steam cracker using ethane feedstock may be far below the costs forusing propane, butanes or naphthas as feedstock(s).

Following thermal cracking of saturated hydrocarbons, the effluent fromthe pyrolysis reactor must be rapidly cooled to a temperature at whichno additional reaction occurs. This rapid cooling may be effected byindirectly cooling the effluent in typical Transfer Line Exchanger(s)(TLE) which generates high pressure steam and then further directlycooled by circulating water created from condensation of steam within aQuench Water Tower.

For gaseous feedstocks (ethane, propane and butanes), a Quench Oil Tower(QOT) may not be required because only small amounts of C5⁺ liquids maybe produced. For these feedstock types, a simple Quench Water Tower(QWT) is used to cool the effluent gas from the TLE.

The cracked gas may be further cooled in the QWT by direct contact withquench water. Typically, the bottoms stream leaving the quench towerfeeds an oil-water separator (OW/S) drum, which function as athree-phase separator, with a light hydrocarbon phase that floats onwater, and the tar which sinks in water, as the bottom phase, and wateras the middle phase. Even in the case of cracking an ethane feed whichmay have a relatively lower tar yield than other feedstocks, the smallamounts of tar may build up and over time and foul downstream units. Inparticular, water leaving the OW/S may contain enough heavy oils andtar, which has a specific gravity close to that of water, to potentiallycause downstream fouling of the quench circuit. This can alsopotentially result in the fouling of downstream heat exchangers andwater stripping towers, which, when fouled, must be taken offline forcleaning.

The gross Quench Water (QW), from the OW/S, may contain residual finesolid particles, unsettled free oil, emulsified oil, and dissolvedhydrocarbons. The majority of this gross QW may be recirculated forlow-level heat recovery within the ethylene plant before returning tothe QWT. The net raw QW may be either: (1) used to generate dilutionsteam for steam cracking as a close-loop system, or (2) purged tobattery limits as an open-loop system. The net QW may be processed toremove the residual suspended solids, as well as free and emulsifiedoil, in order to prevent or reduce fouling in a downstream dilutionsteam generation system. Alternatively, if the excess raw water weresimply purged to battery limits, it would still be necessary to removeorganic impurities (e.g. benzene, dienes, and other carcinogens) to suchan extent that it could be discharged into local streams without causingpollution.

At present, the net QW is treated by coalescing its free and dispersedoil using any combination of the available coalescing technologiesincluding: filter-coalescer, Natco DOX (Dispersed Oil Extraction) unit,and IGF (Induced Gas Floatation). These technologies are effective inremoving most of the free and dispersed oil but remain incapable ofremoving the dissolved unsaturated hydrocarbons. Any remaining dissolvedunsaturated hydrocarbons in the QW may polymerize leading to fouling ofthe steam generation equipment. Additionally, discharges of net QW andblowdowns from dilution steam generators and gaseous hydrocarbonsaturators may have difficulties in meeting the environmentally requiredoil and benzene content.

BRIEF DESCRIPTION OF THE DRAWINGS

These drawings illustrate certain aspects of some examples of thepresent disclosure, and should not be used to limit or define thedisclosure.

FIG. 1 is a schematic illustration of a gas cracking plant comprising adissolved oil removal unit.

FIG. 2 is a schematic illustration of a gas cracking plant comprising adissolved oil removal unit.

FIG. 3 is a schematic illustration of a dissolved oil removal unit.

FIG. 4 is a schematic illustration of a dissolved oil removal unit.

DETAILED DESCRIPTION

The present disclosure is directed to removal of polymerizable compoundsfrom a quench water stream in a gas cracking plant and in one or moreembodiments to a liquid-liquid extractor to remove the polymerizablecompounds. Commercially available technologies in ethylene plants fortreating the net quench water (QW) may involve the removal of suspendedsolids and coalescing dispersed oil without affecting the dissolvedhydrocarbon content. QW may comprise tars, heavy aromatic hydrocarbonswith a specific gravity of greater than 1, gasoline, dissolved oil,dispersed oil, and other hydrocarbon species. The gross QW, from theOW/S, may comprise residual fine suspended solids in the range of 20 to30 ppmw, unsettled oil and grease of 900-1200 ppmw, and total organiccarbon that include both dispersed and dissolved HC's in the range from1500-2000 ppmw carbon. These ranges are merely illustrative and one ofordinary skill would understand that the process disclosed herein may beapplied to ranges that are smaller or larger than those instantlydisclosed. Commercially available technologies may involve addition ofgasoline or other commercial proprietary emulsion breaking chemicals toenhance phase separation, and filters and/or hydro-cyclone followed bycoalescer.

Filter-coalescer units are prevalent in several olefin plants builtprior the 1990's. At the time of the plant constructions, there were nobenzene regulations that had to be met for the water blowdown stream.The filter-coalescer units may include a filter and a coalescer. Thefilter may capture coke fines as particulate matter. Typically, theremay be two sets of filters, a coarse type (e.g., 100-300 microns size)and a fine type (e.g., 10-30 microns). These filters may be made of anysuitable material, including, but not limited to, fabric or fibers, andgenerally may be a cartridge type. Some plants may use metallic filtersthat may be back flushed with QW. This technique may reduce the risk ofbenzene exposure to the operators.

The water from the filter may be transferred to the coalescer, which maybe a horizontal drum or oil-water separator designed to segregate oiland water. The design of the drum may be based on the fundamentalprinciples of Stoke's Law. The separated oil floats to the top and oilfree water is withdrawn from the bottom. Any tar or tar-like compoundscollect in the bottom of the oil-water separator and may be removedintermittently. The coalescer efficiency of oil- water separationdepends, for example, on the density difference of oil and water and howmuch residence time is available. Therefore, coalescers may berelatively large to be effective for this application.

A Dispersed Oil Extractor (DOX) system may be used to remove emulsifiedoil and suspended solids from the QW. The system may comprise a primarygranular media coalescer filled with a multi-layer of different sizegranular material, followed by a vertical coalescer filled with carbonmedia that may further coalesce suspended oil. The oil coalescence maybe finished in a horizontal separator containing a matrix plate sectionand a separation section that allows the separation of the three phases(light oil, treated QW and heavy oil). This system does not removedissolved hydrocarbons from the treated QW.

Another system may include an Induced Gas Floatation (IGF) system. TheIGF may remove emulsified oil and suspended solids from QW. Fine gasbubbles may be distributed uniformly through the fluid volume, providingefficient transport of oil and solids to the liquid surface for removal.When the oil contacts a gas bubble, it wets the surface of the bubble.The oil wetted bubbles may agglomerate due to attraction caused bysurface tension forces and electrically charged particles. These bubblesthen float to the top of the chamber and are skimmed off Suspendedsolids adhere to the bubbles and are skimmed off as well. Froth isremoved via a simple skim trough that simplifies both the operation andmaintenance. Skimming volume and frequency are automatically controlled.

The water leaving this IGF unit may be passed through a filter to polishthe water and remove the remaining emulsified oil in the water.Pecan/Walnut shell media may resist oil fouling better than other media.The media may be cleaned using any suitable technique, including, butnot limited to, back flushing with aromatic oil a few times a year. Onlyabout 5-10% replenishing may be required per year of operation. Theregeneration cycle may comprise a) fluidization; b) discharge to theflare or to the Quench Water Tower, c) settling and normalization. Thefroth collected from the IGF unit may be allowed to settle in a tankbefore the oil is sold as a product. The sludge from the bottom of thetank may be removed periodically and disposed with the heavy oil andtars. An additive may be added prior to the IGF unit to assist in oil &grease separation. Additionally, natural gas, fuel gas, or nitrogen maybe used for flotation. The natural gas or fuel gas may then be burned inthe furnaces. In examples with chemical injection prior to the IGF unitand a filter after the IGF unit, the recovery of hydrocarbons may beabout 98% or greater. IGF treated water typically has less than amount20 ppmw (parts per million by weight) free hydrocarbons.

In some examples, it may be necessary to clean the net QW to removecontamination before the net QW is used for generating dilution steam.Removing contamination may reduce or prevent fouling in downstreamequipment such as a Low Pressure Water Stripper (LPWS), a Dilution SteamGenerator (DSG), or a Gaseous Hydrocarbon Steam Saturator (GHSS).Furthermore, removal of contaminants may allow operation of the LPWS attemperature higher than 125° C., which may reduce the benzene content tobelow the environmental required benzene specification limits of <50ppbw (parts per billion by weight) for blowdown discharge to theenvironment.

The previously mentioned technologies for treating net QW are found tobe inadequate to meet the above two cleanup requirement since they canonly address removal of solids and both the free and dispersed oil. Evenif these coalescing technologies were to operate perfectly, they willleave behind in the partially treated net QW all the dissolvedhydrocarbon in the net QW for dilution steam-make.

In some examples, the performance of a DOX unit in treating net QW fromthe oil-water separator unit may remove total organic carbon (TOC) toabout 21% of the input TOC. Such equipment is available from theSchlumberger Company marketed as NATCO DOX. The dissolved hydrocarbonsmay largely consist of highly soluble unsaturated components of the oilsin the QW, These unsaturated compounds may be highly reactive polymerprecursors represented by styrene and indene as indicative dissolved oilspecies in the aqueous phase.

Styrene polymerization may produce a black or brown hard deposit whilepolyindene polymers may be yellowish. Because of frequent fouling of theDSG in the past, many DSG trays are removed during revamps and in newgrassroot design to avoid fouling and limiting the DSG capacity. Theremoval of trays in the DSG means that any polymer formed may not bedeposited in the DSG, but rather they may be carried with the dilutionsteam to the furnace where they will encounter much higher temperatureand may cause more damaging fouling of the cracking furnace steel tubes.

As a result of the new requirements for low benzene content of <50 ppbwin the blowdown QW discharge and the disadvantages of the prior artprocesses in removing the dissolved polymer precursors from the net QW,an additional process step may be used for the removal of the dissolvedhydrocarbons from the net QW. The combination of the previouslydescribed process steps used to remove the free and dispersed oil fromthe net QW using filter coalescer, DOX, IGF, or a combination thereoftogether with an additional step of extraction of the dissolvedhydrocarbons may remove essentially all hydrocarbons present in the netQW before reaching the DSG or the GHSS. The process will meet the newbenzene levels in the QW blowdown requirements and overcome thedeficiencies of the prior art that resulted in fouling of the DSG andGHSS.

FIG. 1 illustrates a more detailed description of the disclosedtechniques, in accordance with example embodiments. Process 100illustrates a gas cracking process comprising a liquid-liquid extractorand a dilution steam generator. Gaseous hydrocarbon feedstock 105 maycomprise ethane or propane and other trace hydrocarbons as definedwithin the Gas Processors Suppliers Association (GPSA) handbook. Gaseoushydrocarbon feedstock 105 may be delivered to the convection section inthe upper part of the cracking furnaces 110. Gaseous hydrocarbonfeedstock 105 may be first preheated in hydrocarbon preheat banks, notillustrated, prior to mixing with dilution steam 115. The hydrocarbonand dilution steam mixture may then be further preheated sequentially inthe hydrocarbon dilution steam bank before leaving the convectionsection to cross over to the radiant coil inlets.

The heat required for the cracking reaction may be supplied by a radiantsection in the lower part of the steam cracking furnace 110. In someembodiments, the radiant section may comprise floor fired burners. Theburners firing rate may be controlled based on the average coil outlettemperature. Furnace effluent may be rapidly cooled in quench exchangers120. Quench exchangers 120 may comprise any suitable heat exchangerssuch as, for example, double pipe exchangers or horizontal shell andtube transfer line exchanger (TLE) quench exchangers. Boiler feed water121 may be supplied to quench exchanger 120 to generate steam 122 foruse in other processes.

The heat exchanger effluent comprising cracked gasses may then be fed toa quench water tower 125 wherein the heat exchanger effluent may befurther cooled by direct countercurrent contact with quench water 126.The cooled gas from the quench water tower overheads 127 may betransported to a cracked gas compressor. A water and hydrocarbon mixture128, may be collected in the bottom of the quench water tower, which maythen be transported to oil-water separator 130. Oil-water separator 130may separate a heavy phase, comprising tar and coke particles, from thebulk stream. A water-hydrocarbon interface may be established which mayallow for separation of the remaining two phases. In the case ofcracking an ethane feed, light tars may be produced which may have aspecific gravity close to that of water. The tar yield may be highenough to cause the water leaving oil-water separator 130 to causedownstream fouling of the quench circuit. Accumulated tar and cokeparticles 131 may settle out from the quench water in oil-waterseparator 130 which may be stored in barrels or sent to an incineratorfor disposal. A pyrolysis gasoline stream 132 may also be removed fromoil-water separator 130 which may be delivered to a slop oil tank.Pyrolysis gasoline is a naphtha boiling range product with a higharomatics content that may be produced as a side product of the thermalcracking reaction. Oil-water separator 130 may operate in a temperaturerange of about 80° C. to about 90° C. and a pressure within about90-100% of adiabatic saturation.

The hot raw quench water 135 from the oil-water separator 130 may bepumped and split into recirculating hot quench water 145 and a small netquench water NQW 140. The hot quench water 145 may be circulated throughthe quench water users 150 and then be further cooled in cooling waterexchanger 155 to produce quench water 126. Quench water 126 may bereturned to quench water tower 125.

The NQW 140 may be fed to an oil coalescing unit 160 which may separateout the solids, and both the free and dispersed oil and hydrocarbonsfrom NQW 140. Oil coalescing unit 160 may comprise one or morecoalescing units including filter-coalescer unit, Natco DOX (DispersedOil Extraction) Unit, induced gas floatation unit (IGF), or combinationthereof as previously described.

The coalesced NQW 161 from the oil coalescing unit 160 may be treatedfor removal of dissolved hydrocarbon in dissolved oil removal unit 170.Dissolved Oil Removal (DOR) unit 170 may comprise a liquid-liquidextractor and a solvent regenerator. The coalesced NQW 161 may becontacted with aromatic rich solvent in dissolved oil removal unit 170which may extract the unsaturated dissolved hydrocarbons from NQW 161.Treated NQW 171 may be pumped to low pressure water stripper, LPWS, 180.The contaminated solvent from dissolved oil removal unit 170 may bedistilled in a solvent regenerator to separate out the lightcontaminants 172, which may be sent to a flare, and a heavy contaminantsstream 173 comprising spent solvent and dissolved hydrocarbons. Theregenerated solvent stream may be combined with a makeup solvent togenerate a solvent stream 174 that is fed into the dissolved oil removalunit 170.

The low pressure water stripper 180 may heat treated NQW 171 to stripits dissolved hydrocarbons and acid gases such as H₂S and CO₂. Cleanwater 181 from low pressure water stripper 180 may be essentially freeof all volatile hydrocarbons, less than about 15 ppmw, at this pressureof about 10-15 psig. Clean water 181 may be pumped to the dilution steamgenerator (DSG) 190 where it may be boiled to generate dilution steam115. Dilution stream 115 may be transported to the cracking furnaces 110to mix with gaseous hydrocarbon feedstock 105. A small part of the watermay be rejected as dilution steam blowdown 191.

FIG. 2 illustrates a process 200 for gas cracking comprising aliquid-liquid extractor and a gaseous hydrocarbon saturator, inaccordance with example embodiments. Gaseous hydrocarbon feedstock 105,may comprise ethane or propane. Gaseous hydrocarbon feedstock 140, maybe heated in an exchanger 205. Heated hydrocarbon gas 210 may be fed togaseous hydrocarbon saturator 215 where it may be mixed with clean waterstream 181 to evaporate the water. Clean water stream 181 which may beessentially free of hydrocarbons from low pressure water stripper 180.Mixed hydrocarbon and steam stream 220 from gaseous hydrocarbonsaturator 215 may be further heated in heat exchanger 225 to producesuperheated stream 230. Superheated stream 230 may be transported tocracking furnace 105 to crack the gaseous hydrocarbons present insuperheated stream 230. The cracked gas furnace effluent may be rapidlycooled in quench exchanger 120. Quench exchanger 120 may comprise doublepipe exchangers, horizontal shell and tube transfer line heatexchangers, and combinations thereof. The heat may be exchanged againstboiler feed water 121 to generate steam 122.

The process gas may be fed to quench water tower 125 wherein the processgases may be further cooled by direct countercurrent contact with quenchwater 126. The cooled gas from the quench water tower overheads 127 maybe transported to the cracked gas compressor. A portion of the feedstream to quench water tower 125 may dissolve into water present inquench water tower 125. A water and hydrocarbon mixture 128 may collectin the bottom of quench water tower 125 and flow to oil-water separator130. Oil-water separator 130 may be configured as previously describedin FIG. 1. Accumulated tar and coke particles 131 may settle out fromthe quench water in oil-water separator 130. The particles may be storedin barrels or be sent to an incinerator for disposal. Pyrolysis gasoline132 from oil-water separator 130 may be delivered to a slop oil tank.

Hot raw quench water 135 from oil-water separator 130 may be pumped andsplit into recirculating hot quench water 145 and a small net quenchwater NQW 140. The hot quench water 145 may be circulated through thequench water users 150 and cooled in cooling water exchanger 155 andthen returned to the tower.

The NQW 140 may be fed to an oil coalescing unit 160 which may separateout any solids, and both the free and dispersed oil from NQW 140, andmay include one or more coalescing unit including filter-coalescer unit,Natco DOX (Dispersed Oil Extraction) Unit, induced gas floatation unitIGF, or combinations thereof as previously described.

Coalesced NQW 161 from the oil coalescing unit 160 may be treated forremoval of its dissolved hydrocarbon in dissolve oil removal (DOR) unit170 which may comprise a liquid-liquid extractor and a solventregenerator. Coalesced NQW 161 may be contacted with aromatic richsolvent in the liquid-liquid extractor which may extract the unsaturateddissolved hydrocarbons from coalesced NQW 161. Treated NQW 171 from DORunit 170 may flow to the low pressure water stripper LPWS 180. Thecontaminated solvent from dissolved oil removal unit 170 may bedistilled in a solvent regenerator to separate out the lightcontaminants 172, which may be sent to a flare, and a heavy contaminantsstream 173 comprising spent solvent and dissolved hydrocarbons. Theregenerated solvent stream may be combined with a makeup solvent togenerate a solvent stream 174 that is fed into the dissolved oil removalunit 170.

Low pressure water stripper (LPWS) 180 may preheat the water and stripdissolved hydrocarbons and acid gases such as H₂S and CO₂. Clean water181 from low pressure water stripper 180, may be essentially free ofhydrocarbons. Clean water 181 and may be pumped to gaseous hydrocarbonsaturator 215 where it may be mixed with the heated hydrocarbonfeedstock 210. A small part of the water may be rejected as QW blowdown235.

With reference to FIG. 3, dissolved oil removal unit 170 and lowpressure water stripper 180 from FIGS. 1 and 2 are shown in greaterdetail, in accordance with example embodiments. Coalesced NQW 161 fromupstream oil coalescing unit, DOX or IGF, may comprise dissolvedhydrocarbons and trace amount of emulsified oil particularly duringupsets in the coalescing unit. Coalesced NQW 161 may be fed to aliquid-liquid extraction tower 300 where it may be counter-currentlycontacted with an extraction solvent, such as stabilized, hydrogenated,aromatic-rich gasoline, preferably a C₆-C₈ cut, with toluene, or amixture thereof, fed to the top of the extraction tower. Contactingcoalesced NQW 161 with the extraction solvent may remove from the quenchwater the polymer precursors such as styrene, indenes and dienes.Removing the precursors that may polymerize when exposed to hightemperatures in the downstream water stripper and the dilution steamgenerator may reduce the fouling in the equipment.

The liquid-liquid extraction tower 300 may operate counter currently tocontact the net quench water and extraction solvent to reduce emulsionformation. Liquid-liquid extraction tower 300 may operate at a pressureranging from about 2 to about 10 bar gauge and a temperature rangingfrom about 50° C. to about 100° C. Liquid-liquid extraction tower 300may be a multistage mixer-settler type tower, a plate/tray type tower,or a packed tower. The liquid-liquid extraction step may effectivelytransfer the polymerizable styrene, indenes, dienes, carbonyls, andheavy organic molecules from the aqueous phase to the extracting solventphase. By the extraction step, greater than about 90% of thepolymerizable materials may be removed. In some examples, greater thanabout 99% of the polymeric materials and polymer forming styrene,indenes, dienes and aromatic vinyl compounds may be removed. The spentextracting solvent 305 may pass out of the upper part of liquid-liquidextraction tower 300, and may then be passed to the middle part ofextracting solvent regenerator unit 310 for recovery. The resulting,extracted quench water 171 may be removed from the bottom of theextraction tower and may be fed to the top of the low pressure waterstripping unit 180.

Spent extracting solvent 305 and makeup solvent stream 174 may bedistilled and regenerated in extracting solvent regenerator 310 that maycomprise a fractionation column equipped with reboiler 315. Reboiler 315may be heated with desuperheated medium pressure steam, and may be athermosiphon reboiler. Extracting solvent regenerator 310 may operate atany suitable conditions, including, but not limited to, a pressureranging from about 400 mm Hg to about 1 bar gauge and a temperatureranging from about 100° C. to about 160° C. Regenerated extractingsolvent 320 may be removed from the middle chimney tray in solventregenerator 310 and may be recycled back via pump 325 to the bottom ofliquid-liquid extraction tower 300. The overhead of the regenerator 310comprising the light hydrocarbon precursors may be condensed incondenser 330 and sent to the reflux drum 335. A portion of the liquidfrom reflux drum 335 is the reflux liquid 340, which may be pumped viapump 345 and the pumped reflux liquid 350 may be fed back to regenerator310. Purge stream 172 from reflux drum 335 may be either returned to thequench water tower or purged to flare. The bottoms 173 comprising heavyhydrocarbons including polymers and polymer precursors may be removedfor routing to the tar drum (not shown) for disposal.

The net quench water in contact with the extracting solvent inliquid-liquid extraction tower 300 may become saturated with thearomatic components of the extracting solvent. These may be stripped outin low pressure water stripper 180. The steam stripping of the extractedquench water may result in the removal of essentially 99.9% of thebenzene and light materials and potentially more than 99% of the tolueneby mass. In some embodiments, low pressure water stripper 180 may be a10 to 20 tray column that utilizes low-pressure steam 355 added as thevapor phase for stripping.

Low pressure water stripper 180 may be operated at any suitabletemperature, including, but not limited to, a saturation temperatureranging from about 125° C. to about 145° C. to provide improved volatileorganic content (VOC) removal. Higher temperatures may be employed inlow pressure water stripper 180, without fouling, to affect improvedbenzene and toluene removal, because of the removal of the polymerprecursors in the upstream liquid-liquid extraction tower 300. In someembodiments, pressure from about 2 bar gauge to about 3 bar gauge may bemaintained in low pressure water stripper 180 to recycle the overheadvapor stream 360 comprising steam and hydrocarbons to the quench watertower. The stripped bottoms 181 removed from stripper bottom drum 365 isthe treated quench water (pretreated quench water); the treated quenchwater 181 may be pumped via pump 370 into dilution steam generator 190.The treated quench water from dilution steam generator 190 may be heatedto generate steam in boiler 375. The steam is returned to dilution steamgenerator 190, where condensates and any contaminants may fall to thevessel bottom. Dilution steam 380 may be withdrawn from the top.Blowdown 191 may be removed from the bottom. Because of the relativepurity of the NQW feed to the dilution steam generator (DSG), theblowdown may be substantially reduced, and instead of a trayed columnand boiler, only a drum and a boiler may be required to produce dilutionsteam in accordance with embodiments of the present invention. Also theblowdown as disclosed herein may contain <10 ppbw benzene thus it may besafely discharged to the environment, where allowed, or used as waterwash in the cracked gas compressor, or be added as makeup to the coolingtowers.

With reference now to FIG. 4 which is the same as in FIG. 3 except thatthe pumped treated quench water from the low pressure water stripper 180flows to the top of gaseous hydrocarbon saturator 215. Gaseoushydrocarbon saturator 215 may comprise a packed section 400. Gaseoushydrocarbon feedstock 105 may be heated in heat exchanger 205 to produceheated hydrocarbon gas 210 which may subsequently enter the bottom ofthe gaseous hydrocarbon saturator 215 which may flow up the saturatorand counter currently contact the flowing treated clean water 181through packed section 400. The hot hydrocarbon gas evaporates andcarries the water vapor as dilution steam to produce mixed hydrocarbonand steam stream 220. Mixed hydrocarbon and steam stream 220 may flow tocracking furnaces 110. Blowdown 235 may be removed from the bottom ofthe gaseous hydrocarbon saturator 215. Because of the relative purity ofclean water 181 feed to the saturator, the blowdown may contain <10 ppbbenzene thus it may be safely discharged to the environment, whereallowed, or used as water wash in the cracked gas compressor, or beadded as makeup to the cooling towers.

The present disclosure may further comprise one or more of the followingembodiments in any combination.

A system comprising a definitive sequence of unit operations to providean overall treatment method of water conditioning to remove essentiallyall oils and particulate matter from water to allow for the productionof high quality dilution steam for thermal cracking of gaseousfeedstocks towards the production of lower olefins whereby the sequenceof unit operations specifically comprises: a) oily-water separations oftars from heavy aromatics and water by decantation within three separatecompartments whereby the first of three compartments separates tarswhose specific gravity is greater than unity from water and the secondof three compartments separates water from heavy aromatics/gasolinewhose specific gravity is less than unity and the third of threecompartments separates heavy aromatics/gasoline from water, followed by,b) either dispersed oil extractor (DOX) and/or induced gas flotation(IGF), followed by, c) filtration of fine particulate matter from thebulk aqueous phase, followed by, d) dissolved oil removal byliquid/liquid (L/L) extraction using a highly mono-aromatic solvent withcapabilities to regenerate the spent solvent re-use to the L/LExtractor, followed by, e) in-situ coalescence of water from oil and oilfrom water preferably both from the head and heal of the L/L Extractorrespectively or less preferably as external coalescer(s) in the sameposition relative to the extract and raffinate exit streams of the L/LExtractor, followed by, f) low pressure direct or indirect steamstripping to removal volatile organics from the aqueous phase wherebythese organics have a lower vapor pressure than water at said lowpressure conditions, followed by, g) either high pressure indirect steamstripping to vaporize the aqueous phase whereby the residual organicshave a higher vapor pressure than water at said high pressureconditions, or, the application of a feed saturator to vaporize theaqueous phase with feed gas prior to entry to the cracking furnace, and,wherein high quality water is used for dilution steam as diluent for the(gas) cracker plant.

The method described by paragraph [0047] part a, wherein the oil-waterseparations operate at a pressure relative to a temperature approach toadiabatic saturation whereby the operating temperature is typicallyranges from a minimum of 80° C. to a maximum of 90° C. wherebydecantation occurs at a steady state temperature profile using theprinciples of Stoke's Law for the three-phase separation of tars, heavyoils/gasoline and water; however, decantation can more preferably takeplace with two, two-phase whereby the first of two decantationsseparates tars from water and the second of two decantaions separatesheavy oils/gasoline from water.

The method described by paragraph [0047] part b, wherein the dispersedoil extractor (DOX) uses course filtration using specific coalescers,one primary and one secondary whereby the primary initiates coalescenceand removes solids and tars while the secondary serves as an enhancerwith a resultant typical removal of “oil and grease” (O&G) from about1044 wppm to about 12.3 wppm with lesser removal of dissolved oils as“total organic carbon” (TOC) to levels from about 1614 wppm to about 350wppm and finally “total suspended solids” (TSS) from about 22 wppm toabout 3 wppm; however, the application of induced gas flotation (IGF)can be equally applied with similar results but most preferably appliedin series with dispersed oil extractor.

The method described by paragraph [0047] part c, supplements the methodof paragraph [0049] by receiving the aqueous phase from either DOX orIGF at a temperature range at minimum of 80° C. or maximum of 90° C. ata pressure compatible with the overall pressure profile for the purposeof fine filtration for micron size particles of 5 μm or more to allowhigher reliability of coalescence within the next unit operation.

The method described by paragraph [0047] part d, wherein a trayed ormost preferably a packed multi-stage countercurrent L/L Extractor witheither random or structured packing contacting the aqueous phase havingcontained dissolved oils with a highly mono-aromatic solvent preferablybenzene of a mixed benzene, toluene with mix xylenes or most preferablymerchantable grade toluene at a temperature range of about 60° C.-80°C., preferably at 70° C. or most preferably at 80° C. whereby the S/Fratio is most preferably 1:8 and no less operating at elevated pressurebut no higher pressure than available to satisfy the overall pressureprofile wherein said spent solvent is regenerated by atmosphericdistillation (e.g. 760 mm Hg) or more preferably by slight vacuum (noless than 600 mm Hg) to mitigate the fouling tendencies of the residualoils concentrated at the bottoms outlet such that the reboiler operatesas a once-thru reboiler with no more than 15% vaporization but morepreferably less than 15% vaporization.

The method described by paragraph [0047] part e, supplements paragraph[0051] by receiving the aqueous phase from fine filtration to allowcoalescence by a discrete coalescer to remove free oils to the extent oftheir mutual solubility in water with no removal of dissolved oilswhereby in-situ coalescence at head and heal of the L/L Extractorremoves water from oil (solvent) and oil (solvent) from waterrespectively, while the same can be accomplished less preferably usingexternal coalescer(s).

The method described by paragraph [0047] part e, whereby concentrationsof dissolved oils mimicked experimentally by way of contained styreneand indene is less than 1 wppm total within the final sequence oftreatment; more specifically, the water quality for styrene content ofno more than 0.3 wppm from 55 wppm and water quality for indene contentof no more than 0.4 wppm from 410 wppm using a solvent-to-feed (S/F)ratio of no less than 1:8 using either toluene or BTX within a L/LExtractor per the sequence of unit operations as previously described.

The method described by paragraph [0047] part f, supplements paragraph[0049] whereby the extract from the L/L Extractor is now free ofdissolved oils to the extent described by paragraph [0053] such that allremaining hydrocarbons which have a higher vapor pressure than water canbe readily stripped at low pressure wherein atmospheric or slightlyhigher than atmospheric is highly desirable to ensure no light keyhydrocarbons are contained in the aqueous phase for final dilution steamquality.

The method described by paragraph [0047] part g, supplements paragraph[0049] whereby the extract from the L/L Extractor is now free ofdissolved oils to the extent described by paragraph [0051] such that allremaining hydrocarbons which have a lower vapor pressure than water canbe readily stripped at high pressure compatible wherein the pressureprofile for the final unit operation is highly desirable to ensure noheavy key hydrocarbons are contained in the aqueous phase for finaldilution steam quality.

The method for the final unit operation in the sequence described hereinprovides a reject aqueous stream exiting the bottom of the high pressurestripper, when applied, or a reject aqueous stream exiting the bottom ofthe feed saturator, when applied, whereby the quality of reject water issuitable for total recovery and return to the first unit operation(oily-water separation) thereby allowing for no loss of water from thesystem resulting in no make-up water to the system. To permitsteady-state operation of the oily-water separation within the firstunit operation, cooling of the reject water from either high pressurestripping or feed saturation is required to ensure temperature profilecompatibility between unit operations, i.e. oily-water separation anddilution steam production.

EXAMPLES

To facilitate a better understanding of the present embodiments, thefollowing illustrative examples of some of the embodiments are given. Inno way should such examples be read to limit, or to define, the scope ofthe disclosure.

The removal of styrene and indene from the quench water (QW) stream inthe example embodiments may be further illustrated by the followingexamples wherein all percentages are by weight unless specifiedotherwise. A gas chromatography (GC) method was used to evaluate thecomposition of styrene and indene in the quench water stream. Liquidsamples were collected by filling sample bottles from the extractorcolumn overhead outlet. Each sample was then analyzed by GC to determinethe amount of styrene and indene in the quench water.

The Extraction Column consisted of 5 cm inside diameter stainless steelcolumn, packed with 6 mm Propak® stainless steel packing to a height of90 cm. Quench water that contained 55 ppmw (parts per million by weight)styrene and 410 ppmw indene was allowed to flow down the column packingcontacting counter currently against the up flowing hydrocarbon solvent(toluene or BTX). The extraction column was operated at 0.9 barg (bargauge) and temperature of 40° C. The solvent flow rate to the bottom ofthe extraction column was adjusted to flow at a predetermined rate foreach test run; while the liquid quench water flow to the top of thecolumn was set to flow at a rate of 12±1 liter/hr. for all test runs;the flow rates to the column were calculated for operation well belowthe flooding regime of the packing.

The treated quench water from the extractor flowed directly to the topof the quench water stripper operated at 0.2 barg. The stripperconsisted of 5 cm inside diameter stainless steel column, packed with 6mm Propak® stainless steel packing to a height of 90 cm. The quenchwater was reboiled at the bottom of the stripper; the generated steamflowed up the column stripping the more volatile residual styrene andindene from the liquid quench water flowing down the column through thepacked section. The styrene and indene were stripped to <<0.3 ppmw.

The solvent from the extractor was collected in a drum and then pumpedto the middle of the of the regenerator column with a runback, vented,condenser operated at 0.3 barg. The regenerator consisted of 5 cm insidediameter stainless steel column, packed with 6 mm Propak® stainlesssteel packing with a feed section placed in the middle of the columnwith a packed height of 60 cm above the feed section and a packed heightof 60 cm below the feed section. The solvent was distilled and thedissolved light gases that were picked up by the solvent from the QWduring extraction were vented from the condenser vent. The heavy styreneand indene was purged with some of the solvent from the bottom of theregenerator column. The purified solvent was taken out of the column andkept in a storage drum for use in the next test run.

Example 1

The extraction column was operated with quench water flow of 12±1liter/hr. containing 55 ppmw styrene and 410 ppmw indene which was fedto the top of the column, and contacted counter-currently with toluenesolvent fed to the bottom of the packing at a rate of 12±1 liter/hr. TheToluene to quench water volumetric ratio is 1:1. The styrene and indenefrom the quench water is extracted by the toluene, and theirconcentration in the quench water is depleted at the column bottomoutlet stream, measured an average 0.41 ppmw styrene, and an average of0.45 ppmw indene. The quench water from the extractor was fed directlyto the top of quench water stripper where it was stripped by steamgenerated in the bottom reboiler. The concentrations of styrene andindene were further reduced in the quench water stream leaving thebottom of the stripper to an average 0.12 ppmw styrene, and an averageof 0.16 ppmw indene. Data for Example 1 is shown in Table 1.

TABLE 1 LLE inlet QW styrene 55 ppmw indene 410 ppmw QW flow rate 12 ± 1liter/hr. Toluene flow rate 12 ± 1 liter/hr. Toluene/QW vol Ratio 1:1Extractor ID 5 cm Packed Height 90 cm packing type Propak ® 6 mm LLEoutlet QW LPWS outlet QW Run time styrene indene styrene indene minutesRun # ppmw ppmw ppmw ppmw 88 1 0.7 0.6 0.2 0.4 82 2 0.3 0.5 0.1 0.1 75 30.33 0.45 0.1 0.1 88 4 0.3 0.3 0.1 0.1 80 5 0.4 0.38 0.1 0.1 Avg 83 0.410.45 0.12 0.16

Example 2

The extraction column was operated with quench water flow of 12±1liter/hr. containing 55 ppmw styrene and 410 ppmw indene which was fedto the top of the column, and contacted counter-currently with toluenesolvent fed to the bottom of the packing at a rate of 2.5±0.2 liter/hr.The toluene to quench water volumetric ratio was 1:4.8 The styrene andindene from the quench water was extracted by the toluene, and theirconcentration in the quench water was depleted at the column bottomoutlet stream, measured an average 0.91 ppmw styrene, and an average of0.74 ppmw indene. The quench water from the extractor was fed directlyto the top of quench water stripper where it was stripped by steamgenerated in the bottom reboiler. The concentrations of styrene andindene were further reduced in the quench water stream leaving thebottom of the stripper to an average 0.2 ppmw styrene, and an average of0.2 ppmw indene. Data for Example 2 is shown in Table 2.

TABLE 2 LLE inlet QW styrene 55 ppmw indene 410 ppmw QW flow rate 12 ±1  liter/hr. Toluene flow rate 2.5 ± 0.2 liter/hr. Toluene/QW vol Ratio1:4.8 Extractor ID 5 cm Packed Height 90 cm packing type Propak ® 6 mmLLE outlet QW LPWS outlet QW Run time styrene indene styrene indeneminutes Run # ppmw ppmw ppmw ppmw 81 1 1.2 0.8 0.2 0.4 90 2 1 0.9 0.30.1 75 3 0.53 0.6 0.2 0.1 80 4 0.9 0.65 0.1 0.2 Avg 82 0.91 0.74 0.200.20

Example 3

The extraction column was operated with quench water flow of 12±1liter/hr. containing 55 ppmw styrene and 410 ppmw indene which was fedto the top of the column, and contacted counter-currently with toluenesolvent fed to the bottom of the packing at a rate of 1.5±0.1 liter/hr.The Toluene to quench water volumetric ratio was 1:8. The styrene andindene from the quench water was extracted by the toluene, and theirconcentration in the quench water is depleted at the column bottomoutlet stream, measured an average 1.13 ppmw styrene, and an average of0.9 ppmw indene. The quench water from the extractor was fed directly tothe top of quench water stripper where it is stripped by steam generatedin the bottom reboiler. The concentrations of styrene and indene werefurther reduced in the quench water stream leaving the bottom of thestripper to an average 0.23 ppmw styrene, and an average of 0.3 ppmwindene. Data for Example 3 is shown in Table 3.

TABLE 3 RUNS TEST 3 QUENCH WATER TREATIN DISSOLVED OIL REMOVAL UNIT(DOR) LLE inlet QW styrene 55 ppmw indene 410 ppmw QW flow rate 12 ± 1 liter/hr. Toluene flow rate 1.5 ± 0.1 liter/hr. Toluene/QW vol Ratio 1:8Extractor ID 5 cm Packed Height 90 cm packing type Propak ® 6 mm LLEoutlet QW LPWS outlet QW Run time Styrene indene styrene indene minutesRun # ppmw ppmw ppmw ppmw 72 1 1.5 1 0.2 0.4 75 2 1.2 0.9 0.3 0.3 82 30.7 0.7 0.2 0.3 80 4 1.1 1 0.2 0.2 Avg 77 1.13 0.90 0.23 0.30

Example 4

The extraction column was operated with quench water flow of 12±1liter/hr. containing 55 ppmw styrene and 410 ppmw indene which was fedto the top of the column, and contacted counter-currently with BTXsolvent fed to the bottom of the packing at a rate of 2.5±0.2 liter/hr.The BTX to quench water volumetric ratio was 1:4.8. The styrene andindene from the quench water was extracted by the BTX, and theirconcentration in the quench water was depleted at the column bottomoutlet stream, measured an average 0.75 ppmw styrene, and an average of1.8 ppmw indene. The quench water from the extractor was fed directly tothe top of quench water stripper where it is stripped by steam generatedin the bottom reboiler. The concentrations of styrene and indene werefurther reduced in the quench water stream leaving the bottom of thestripper to an average 0.28 ppmw styrene, and an average of 0.25 ppmwindene. Data for Example 4 is shown in Table 4.

TABLE 4 RUNS TEST 4 QUENCH WATER TREATING DISSOLVED OIL REMOVAL UNIT(DOR) LLE inlet QW styrene 55 ppmw indene 410 ppmw QW flow rate 12 ± 1 liter/hr. BTX flow rate 2.5 ± 0.2 liter/hr. BTX/QW vol Ratio 1:4.8Extractor ID 5 cm Packed Height 90 cm packing type Propak ® 6 mm LLEoutlet QW LPWS outlet QW Run time Styrene indene styrene indene minutesRun # ppmw ppmw ppmw ppmw 85 1 0.8 2.1 0.3 0.4 78 2 1 1.9 0.3 0.2 75 30.7 1.6 0.2 0.2 85 4 0.5 1.6 0.3 0.2 Avg 77 0.75 1.8 0.28 0.25

Example 5

The extraction column was operated with quench water flow of 12±1liter/hr. containing 55 ppmw styrene and 410 ppmw indene which was fedto the top of the column, and contacted counter-currently with BTXsolvent fed to the bottom of the packing at a rate of 1.5±0.1 liter/hr.The BTX to quench water volumetric ratio was 1:8. The styrene and indenefrom the quench water is extracted by the BTX, and their concentrationin the quench water was depleted at the column bottom outlet stream,measured an average 1.43 ppmw styrene, and an average of 2.23 ppmwindene. The quench water from the extractor was fed directly to the topof quench water stripper where it is stripped by steam generated in thebottom reboiler. The concentrations of styrene and indene were furtherreduced in the quench water stream leaving the bottom of the stripper toan average 0.28 ppmw styrene, and an average of 0.35 ppmw indene. Datafor Example 5 is shown in Table 5.

TABLE 5 RUNS TEST 5 QUENCH WATER TREATING DISSOLVED OIL REMOVAL UNIT(DOR) LLE inlet QW styrene 55 ppmw indene 410 ppmw QW flow rate 12 ± 1 liter/hr. BTX flow rate 1.5 ± 0.1 liter/hr. BTX/QW vol Ratio 1:8Extractor ID 5 cm Packed Height 90 cm packing type Propak ® 6 mm LLEoutlet QW LPWS outlet QW Run time Styrene indene styrene indene minutesRun # ppmw ppmw ppmw ppmw 70 1 1.5 2.5 0.3 0.4 75 2 1.4 2 0.3 0.3 88 31.7 1.9 0.2 0.3 78 4 1.1 2.5 0.3 0.4 Avg 78 1.43 2.23 0.28 0.35

SUMMARY OF RESULTS

Results of the Examples 1, 2, 3, 4 and 5 show that removal of styreneand indene are almost complete when the quench water from the DOX/IGFunits is extracted by light aromatic hydrocarbon solvents e.g. tolueneand BTX. DOR removes >99% of the incoming polymer precursors (styreneand indene) in the quench water from the DOX/IGF units. The Solventcould be either toluene or BTX. DOR will prevent fouling in the LPWS andthe dilution steam generating equipment both the DSG and the Saturators.The results are summarized in Table 6.

TABLE 6 Inlet QW from DOR-LLE DOR-LPWS RUNS DOX/IGF Extractor OutletOutlet TEST Extraction Solvent/QW Styrene Indene Styrene Indene StyreneIndene # Solvent Vol Ratio ppmw ppmw ppmw ppmw ppmw ppmw 1 Toluene 1:155 410 0.41 0.45 0.12 0.16 2 Toluene 1:4.8 55 410 0.91 0.74 0.20 0.20 3Toluene 1:8 55 410 1.13 0.90 0.23 0.30 4 BTX 1:4.8 55 410 0.75 1.8 0.280.25 5 BTX 1:8 55 410 1.43 2.23 0.28 0.35

What is claimed is:
 1. A method for removing dissolved hydrocarbons fromwater comprising: mixing a gaseous hydrocarbon stream with a clean steamstream to produce a mixed hydrocarbon stream; cracking the mixedhydrocarbon stream in a cracking furnace to produce a cracked gaseffluent; quenching the cracked gas effluent in a quench water towerwith quench water to produce a quenched gas stream and a spent quenchwater stream comprising water, tars, heavy aromatic hydrocarbons,gasoline, dissolved oil, and dispersed oil; decanting the spent quenchwater stream to remove at least a portion of the tars, the heavyaromatic hydrocarbons, and the gasoline from the spent quench waterstream to produce a decanted spent quench water stream; feeding thedecanted spent quench water stream to a dispersed oil removal unitwherein the dispersed oil removal unit removes at least a portion of thedispersed oil from the decanted spent quench water to produce acoalesced quench water stream and wherein the dispersed oil removal unitis selected from the group consisting of a filter coalescer unit,dispersed oil extractor unit, induced gas floatation unit, andcombinations thereof; and feeding the coalesced quench water stream to aliquid-liquid extraction unit wherein the liquid-liquid extraction unitremoves at least a portion of the dissolved oil and produce an extractedeffluent stream; feeding the extracted effluent stream to a low pressurewater stripper wherein the effluent stream is stripped using a strippingsteam stream to produce a cleaned water effluent; vaporizing the cleanedwater effluent in a dilution steam generator to produce the clean steamstream.
 2. The method of claim 1 wherein the step of decanting operatesat a temperature of about 80° C. to about 90° C. and a pressure withinabout 90-100% of adiabatic saturation.
 3. The method of claim 1 whereinthe dispersed oil removal unit comprises the filter coalescer unit, andwherein the filter coalescer unit comprises a primary coalescer andsecondary coalescer and wherein the filter coalescer reduces a totalorganic carbon level to less than about 350 ppmw.
 4. The method of claim1 wherein the liquid-liquid extraction unit comprises a liquid-liquidextraction column and a solvent regenerator.
 5. The method of claim 4wherein the liquid-liquid extraction column receives the coalescedquench water stream and counter currently contacts the coalesced quenchwater steam with an aromatic solvent.
 6. The method of claim 5 whereinthe aromatic solvent is a mono-aromatic solvent selected from the groupconsisting of mono-aromatic C₆-C₈ cut gasoline, toluene, benzene,xylene, and combinations thereof.
 7. The method of claim 1 wherein theextracted effluent stream comprises less than 1.5 ppmw styrene and lessthan 3 ppmw indene.
 8. The method of claim 1 wherein a steam blowdownstream from the dilution steam generator contains less than 10 ppmwtotal organic carbon.
 9. A method for removing dissolved hydrocarbonsfrom water comprising: heating a gaseous hydrocarbon stream to produce aheated hydrocarbon stream and feeding the heated hydrocarbon stream to ahydrocarbon saturator; introducing a cleaned water effluent into thehydrocarbon saturator wherein the heated hydrocarbon stream and cleanedwater effluent mix and vaporize at least a portion of the water andproduce a mixed hydrocarbon stream; cracking the mixed hydrocarbonstream in a cracking furnace to produce a cracked gas effluent;quenching the cracked gas effluent in a quench water tower with quenchwater to produce a quenched gas stream and a spent quench water streamcomprising water, tars, heavy aromatic hydrocarbons, gasoline, dissolvedoil, and dispersed oil; decanting the spent quench water stream toremove at least a portion of tars, heavy aromatic hydrocarbons, andgasoline from the spent quench water stream to produce a decanted spentquench water stream; feeding the spent quench water stream to adispersed oil removal unit wherein the dispersed oil removal unitremoves at least a portion of the dispersed oil from the decanted spentquench water to produce a coalesced quench water stream and wherein thedispersed oil removal unit is selected from the group consisting offilter coalescer unit, dispersed oil extractor unit, induced gasfloatation unit, and combinations thereof; and feeding the coalescedquench water stream to a liquid-liquid extraction unit wherein theliquid-liquid extraction unit removes at least a portion of thedissolved oil and produces an effluent stream comprising less than 4ppmw total organic carbon_(; and) feeding the effluent stream to a lowpressure water stripper wherein the effluent stream is stripped using astripping steam stream to produce the cleaned water effluent.
 10. Themethod of claim 9 wherein the step of decanting operates at atemperature of about 80° C. to about 90° C. and a pressure within about90-100% of adiabatic saturation.
 11. The method of claim 9 wherein thedispersed oil removal unit comprises the filter coalescer unit, andwherein the filter coalescer unit comprises a primary coalescer andsecondary coalescer and wherein the filter coalescer reduces a totalorganic carbon level to less than about 350 ppmw.
 12. The method ofclaim 9 wherein the liquid-liquid extraction unit comprises aliquid-liquid extraction column and a solvent regenerator.
 13. Themethod of claim 12 wherein the liquid-liquid extraction column receivesthe coalesced quench water stream and counter currently contacts thecoalesced quench water stream with an aromatic solvent.
 14. The methodof claim 13 wherein the aromatic solvent is a mono-aromatic solventselected from the group consisting of mon-oaromatic C₆-C₈ cut gasoline,toluene, benzene, xylene, and combinations thereof.
 15. The method ofclaim 9 wherein the extracted effluent stream comprises less than 1.5ppmw styrene and less than 2.3 ppmw indene, and less than 4 ppmw totalhydrocarbons.
 16. The method of claim 9 wherein a steam blowdown streamfrom the dilution steam generator contains less than 10 ppmw totalorganic carbon.
 17. A system for removing dissolved hydrocarbons fromwater comprising; a gas cracking furnace configured to crack a gaseoushydrocarbon stream; a quench water tower configured to quench aneffluent stream from the gas cracking furnace; a decanter configured todecant a spent quench water stream from the quench water tower; adispersed oil removal unit configured to remove at least a portion of adispersed oil from a decanter effluent stream; a liquid-liquid extractorunit configured to remove at least a portion of a dissolved oil from adispersed oil removal unit effluent stream; and a low pressure waterstripper configured to contact a liquid-liquid extractor effluent streamwith a steam stream to produce a stream of cleaned water effluentwherein the cleaned water effluent contains less than 0.3 ppmw styreneand 0.35 indene with a total organic carbon less than 0.75 ppmw.
 18. Thesystem of claim 17 wherein the liquid-liquid extractor unit comprises aliquid-liquid extraction column and a solvent regenerator.
 19. Themethod of claim 18 wherein the liquid-liquid extraction column isconfigured to receive the dispersed oil removal unit effluent stream andcounter currently contact the dispersed oil removal unit effluent streamwith an aromatic solvent.
 20. The system of claim 17 further comprisinga dilution steam generator configured to generate stream from thecleaned water effluent.